The invention relates to a subsea process assembly which can be used when extracting materials such as hydrocarbons from subsea environments and, in particular, to an assembly which separates a multiphase flow into individual component flows for further supply to specific locations.
In general, the current practice for development of subsea hydrocarbon fields is on a macro field approach which uses a plurality of subsea wells connected through a subsea infrastructure, pipelines and risers to a surface process facility, such as a floating production vessel or a platform. In many locations, especially in remote areas, the proportion of gas and water within the fluid produced by the well is significant and is generally a surplus product, when compared to the oil which it is usually desired to retrieve. The gas and water has to be safely and cleanly disposed of in a manner which does not damage the environment.
A solution for such a system is that gas and water which have been taken out of the well and which are separated at the surface can be pumped back to the seabed to be reinjected at the seabed into subsea wells. This reinjection reduces the rate of decline of the reservoir pressure allowing the field to produce longer. To increase the rate of production, energy must be supplied to the production steam using either downhole or seabed methods.
Overall, the current approach requires a complex field production system which has numerous pipelines, thus incurring a high field capital expenditure and operational expenditure. This high expenditure reduces the commercial ceiling at which the field can be operated viably. As the field matures and production declines, a level is reached at which considerable resources are left in place but at which it is no longer commercially viable to operate the well.
Conventionally, the flow which is achieved from a subsea well is directed to a surface production vessel. Back pressure on the well reduces the production rate and brings on an early decline of the wells flowing life as the reservoir pressure at the bottom of the well must overcome the hydrostatic head and the pressure caused by friction. Therefore the well depth, the distance along the seabed and the water depth are all contributing factors against the reservoir pressure. At a certain stage, the well ceases to produce a useable flow when a significant proportion of the desired fluid remains in the reservoir area drained by the well. Energy can be added to the production stream, either downhole, at the wellhead or in the riser. The input of energy increases the cost of the well, thereby reducing the commercial viability of the well and, in some cases, the entire field.
In deep water or for wells at a considerable distance, such as over a number of kilometres from the surface production vessel, the production rate decline or the energy input causes the commercial value of a field to be reduced. The early non-viability of the field means considerable valuable resources such as the non recovered natural resources are left in situ. Accordingly, and especially in deep water, the limited production rates, the early decline and the higher costs result in an increased investment requirement with a lower rate of return. This ensures that small and medium sized fields cannot be exploited fully, if at all, using current practices.
When wells are at a considerable horizontal distance along the seabed from the surface production vessel, a number of significant problems such as slugging, hydrates, waxing and an increased back pressure are caused by the distance that the production fluid must travel. In addition, using gas artificial lift in the well can exacerbate these problems causing pipelines to require higher specifications and larger diameters, thereby increasing the cost.
In order to maximise the production capability of a well, well operators are considering solutions which are based on the macro field approach and these include downhole gas lift or pumping, seabed drive, multiphase pumping, gas/liquid separation, hydrocarbon/water separation, individual well gas/liquid separation and three phase separation.
As the pressure in the reservoir declines and at different rates in different parts of the field, the volume produced from the wells will also decline. This also applies in reverse to the injection wells. To maintain an effective production rate will require the addition of artificial lift in the wells that will increase the seabed wellhead flowing pressure. This means that, in pumped wells, a considerable amount of gas will still be in solution at the wellhead.
Downhole pumping typically uses either electric submersible pumps or hydraulic submersible pumps which have to be installed in all commingled wells. The reasons for this is that unpressurised wells cannot flow into a pumped pressurised commingled system. Therefore, a totally pumped field approach has to be taken and pumping has to be installed in some wells that could flow naturally or they need their own pipeline which is very costly. Accordingly, energy and therefore costs are spent on wells which did not require them. These pumps are effective because they are preferably set in the well below the gas bubble point and therefore only have to pump a liquid. Also, the same subsea infrastructure, pipelines and riser systems are still required. Accordingly, the pumping requirements add to the conventional field capital expenditure and also increase the operational expenditure of the field.
In a macro field approach, the wells produce flowing up to the subsea trees along to a manifold for commingling where the flow from individual wells is commingled and then the multiphase fluid flows to the surface via pipelines and risers. For commingling to occur, higher and medium pressured wells need to be choked back to the lowest pressure of a commingled well, thereby losing energy from the flow stream. To reduce the back pressure caused by the pipelines, methods for providing energy to the flow stream downstream of the manifold, such as additional pumps, may be used. As the fluid flows up the well the gas will come out of solution once it is above the bubble point, thereby causing a gas/liquid flow at the wellhead. However, such multiphase pumps require additional energy which increases the cost of this approach. The requirements for pumping this free gas are very different and, in many cases, opposite to those required for pumping liquid and therefore there is a design conflict and, at best, only a poor compromise can be achieved. Therefore it is preferable to separate the fluid into gas and liquid which can be directed to suitable gas pumps and liquid pumps. As friction losses along a pipeline reduce the pressure, more and more gas comes out of the liquid solution, possibly forming 50 to 100 metre slugs of gas. It should be considered that this gas does not need pumping due to the low gas friction factor and low gas hydrostatic head, and can ficely travel along its own pipeline. It is the liquid slugs that have to be pushed along by the compressed gas. Accordingly, the energy used by a multiphase pump to compress the gas to achieve a pressurised multiphase flow is unnecessary if a separate gas flow line is used.
Subsea gas/liquid separation and pumping partially takes advantage of the wellhead at the seabed and water depth. The gas is separated at a lower pressure than the lowest pressure point in the pumped liquid pipeline. Such a system is described in U.S. Pat. No. 4,900,433 and this uses drilling practices and a conventional subsea conductor as a separator housing. Due to the conductor size, a maximum throughput of about 30,000 barrels per day is what can be expected from such a system. The system shown in U.S. Pat. No. 4,900,433 follows conventional practices in flowing to a surface installation but now requires two small pipelines, one for gas and one for liquid, instead of one large multiphase production pipeline.
An alternative separation approach is a hydrocarbon/water separation system. The reason for separating the water from the hydrocarbon is that, when the wells are produced into the system, surface installations need not handle the increased volume of fluid, in particular, caused by the water. By reducing the water at the seabed, the surface installation can operate on a greater number of wells. Oil/water separators are usually gravity separators and require sufficient standing time for the hydrocarbons to float up and the water to sink down. The water is then pumped into a water injection well with the unassisted hydrocarbons flowing in a pipeline to the surface vessel. The gravity multiphase separator does not provide energy to the well stream, except by the effect of later allowing the elimination of the hydrostatic head caused by the removal of the partial pressure exerted by the water in the multiphase fluid. This approach is a solution to solve a specific field symptom such as a production fluid train bottleneck caused by a standard macro field system approach. To increase the production rate, the multiphase hydrocarbon flow can be pumped.
Three phase separation has been attempted and this has been based on a macro field approach with the objective of using horizontal gravity separators, similar to those used on the surface but now on the seabed.
An alternative approach is covered in U.S. Pat. No. 4,848,475. A production and process method is described which utilises single units from U.S. Pat. No. 4,900,433 for each well prior to the flow from the well entering respective gas and liquid pipelines. The individual units allow wells to flow at their maximum production rate with the separator operating pressure being dropped to the allowable pressure to deliver the gas, and the pumped liquid to the surface where further separation on the surface vessel can occur. Accordingly, the deeper the water in which the well is located, the more effective this system is at reducing the individual back pressure on a well. This can delay the need for artificial lift, such as gas lift or downhole pumping, and reduces the reliability issues due to the reduction in the downhole complexity. However, the disadvantage of such a system is that the capital expenditure is extremely high and the complexity of operating such a system are significant. This form of operation has only been considered on a macro approach and therefore considerable energy will need to be supplied to each unit to deliver the liquid back to the surface and on the surface for reinjection.
To achieve separation of gases and liquids, several parameters must be met. Typically in oil wells, some gas will be in solution in the water and oil mixture and the amount of gas in solution is dependent on the pressure of the fluid. In order to separate the gas from the liquid, the pressure must be reduced, thereby lowering the bubble point and allowing gas bubbles to form. The pressure level will set the amount of the gas which is released from the solution and no further gas will be given up until the pressure of the liquid is reduced further. Once gas has been released, it is slow to be reabsorbed into the liquids and therefore repressuring the gas and injecting it into the liquid line will not prevent separate two phase flow and the forming of slug flows.
Once the gas bubbles have formed, the difference in density of the gas to the liquid is significant and this means that the gas will separate readily from a liquid which can be achieved under gravity in approximately a number of seconds for a small volume. Again this time increases as the volume is increased, thereby requiring a large and costly system.
The friction in a horizontal pipeline will cause the pressure in the fluid flow along the pipeline's length to decrease and therefore, even if all of the free gas is removed at the start of the pipeline, a further release of gas will occur along the pipeline due to the pressure drop and this will collect and form a slug, especially in the upper part of an undulation in a pipeline. Each upper part of an undulation will cause a pressure drop in its own right, thereby resulting in a higher pressure being required at the head of the pipeline to move the fluid. To prevent this from occurring, the pressure of the fluid at the wellhead is preferably reduced beyond the lowest pressure point in the pipeline. Alternatively, if a certain amount of gas is required at the surface facility, then the pressure at the head of the pipeline need not be as low but against the penalty of having a higher wellhead flowing pressure.
In a riser, the pressure change or drop is considerable due to the hydrostatic gradient. Gas breakout in the riser or just prior to the riser base will reduce the density of the fluid and of the hydrostatic head and will therefore cause gas lift in the riser. This is acceptable if the gas is required at the surface facility but, if not, then top side separation facilities, pumping equipment, a gas re-injection riser and a gas pipeline back to the wellhead site are also required.
For separation of liquids, it is not possible to use differences in pressure changes as this has little effect on the liquid density. Accordingly, the ability of molecules to move freely depends on the difference in mass, the viscosity of the prime liquid and the surface tension. By increasing the droplet size and its ability to coalesce, a greater mass force is available to overcome the restraining forces, thereby helping the fluids to separate. The ability to allow a fluid to coalesce and collect on wetted surfaces, walls or plates also improves separation.
To achieve separation of a multiphase flow, a first step must be to create a low pressure physical state by first dropping the pressure at the seabed to the surface delivery point requirement. Turbulent flow will continue the mixing and therefore a large volume is required into which the flow passes to allow the fluid flow to stabilise and form a uniform profile. A low velocity and a steady flow encourages such a profile. As mentioned above, separation is typically dependent on mass. A simple technique therefore is to use a sealed settling tank in which gas is quickly given up but, for different liquids, the velocity of the flow has to be reduced drastically to allow effective gravitational separation. This therefore results in large tanks or a very small throughput of separated fluids. This has serious limiting factors subsea due to collapse and burst requirements.
However, if a fluid is rotated or allowed to rotate by tangentially entering a circular container, the gravitational force can be significantly increased from normal earths gravity to approximately ten fold or higher i.e. 100 or 1000. By increasing the force, the separation process can be speeded up and this ensures that small fluid containers can be used. Cyclones or a fluid vortex created in a cylinder are effective methods and these reduce the time required for separation but these can only handle a small volume of fluid and at specific parameters.
At high gravitational forces, typically above 20 G, shear forces are created in a moving fluid compared to a rotating stationary fluid in a centrifuge. These do not effect solids in the liquid but will break down the size of liquid droplets, and possibly create an emulsion. Reduced droplet sizes will considerable extend the time required to achieve separation. Therefore, creating a very high gravity force is effective for removing solids. For liquids, efficient separation of the flow stream occurs between 10 and 20 G.
In the macro field concept, the producing wells are choked down to allow commingling with the flow from the lowest pressured well. The commingled multiphase flow to a platform then enters a surface installation field separator to separate off the gas and to allow liquid pumps to pressurise efficiently the respective fluid phases to allow for production or re-injection. The pressure in a gas re-injection line or a water-reinjection line supplied by the surface installation has to be sufficiently high to meet the injection pressures of the highest pressurised injection well. This therefore requires chokes on the re-injection wells that have a lower injection pressure. This shows that in the macro field well stream system, energy is lost that then has to be replaced by pumping, and energy has to be provided to pump up the re-injection phases with a considerable amount being lost on the low pressured injection wells.
Currently the tendency is to flow all the produced fluids to the surface installation because of the magnitude of the cost and the ability to operate and control a macro subsea field separation system.